This disclosure relates to determining drilling mud contamination of native formation fluids downhole.
This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as an admission of any kind.
Fluid sampling may be used in a wellbore in a geological formation to locate hydrocarbon-producing regions in the geological formation, as well as to manage production of the hydrocarbons in these regions. As such, formation fluid (e.g., drilling mud contaminated formation fluid or uncontaminated (native) formation fluid) that is generally of greatest interest for sampling or testing is the native reservoir fluid (e.g., water, gas, oil, etc.). To sample or test the formation fluid, a downhole acquisition tool may be moved into the wellbore to draw in the fluid.
Fluids other than the native reservoir fluid may contaminate the native reservoir fluid. Drilling muds, for example, may be used in drilling operations to mechanically power rotation of a drill bit and help remove rock cuttings out of the wellbore. The fluid drawn from the wellbore thus may be a mixture of native reservoir fluid and drilling mud filtrate. Of certain concern are oil-based mud drilling fluids that may be miscible with certain native reservoir fluids (e.g., oil and gas). The miscibility of the oil-based mud and the reservoir fluid may cause difficulties in evaluation of the reservoir fluid for assessing the hydrocarbon regions, in particular the region's economic value.